Methods for Determining an Optimal Surfactant Structure for Oil Recovery

ABSTRACT

Methods for determining an optimal surfactant structure for oil recovery are described. These methods systematically evaluate surfactants&#39; phase behavior at ambient and at reservoir conditions; cloud point from ambient to reservoir conditions; dynamic interfacial tension at ambient and at reservoir conditions, including crude oil bubble images and fitting drop profiles; static contact angles at ambient conditions and dynamic contact angles at reservoir conditions; spontaneous imbibition at ambient conditions; and forced imbibition at reservoir conditions.

FIELD OF THE INVENTION

The present invention relates to methods for evaluating an optimalsurfactant structure for oil recovery through a systematic evaluation ofsurfactants' phase behavior, cloud point, dynamic interfacial tension,dynamic contact angle, spontaneous imbibition, and forced imbibition.

BACKGROUND OF THE INVENTION

The United States' projected annual energy growth from 2010 through 2035is 0.3%, from which 37% will be produced from petroleum resources(Annual Energy Outlook, U.S. Energy Information Administration,Technical Report, 2012). Chemical flooding, an enhanced oil recovery(EOR) method, has been used to improve oil production from conventionalreservoirs (D. O. Shah, and R. S. Schechter, Improved oil recovery bysurfactant and polymer flooding, Academic press, Inc., New York, 1977).Surfactants have been used as EOR agents to decrease interfacial tension(IFT) between oil and brine, leading to an increase in surface area ofthe oil droplets (smaller droplets) and higher oil production (J.Eastoe, Advanced surfactants and interfaces, Bristol UK, 2003).

Oil production from ultra-tight reservoirs is rapidly growing and willdominate in the next 10-15 years in the United States (AEO 2013 EarlyRelease Overview, U.S. Energy Information Administration, TechnicalReport, 2013). However, ultra-tight reservoirs have a complicatedmineralogy including clay minerals and clastic minerals like quartz,feldspar, and calcite. Moreover, ultra-tight reservoir rocks haveinterstitial pore sizes ranging from 1-3 nm to 400-750 nm (C. Zou,Unconventional Petroleum Geology, Newnes, 2013). The small interstitialpore sizes lead to high capillary pressures, which act as a barrier tofluid mobility in ultra-tight reservoirs. Horizontal drilling andhydraulic fracturing processes to enhance the reservoir permeabilityovercome the barrier only partially.

In hydraulic fracturing, reservoir rock is cracked by pumping fluidsinto the wellbore and rock formation. Fracturing fluids comprisemunicipal water, proppant, and chemical additives such as surfactants(C. Clarck, A. Burnham, C. Harto, and R. Homer, Hydraulic fracturing andshale gas production: Technology, Impacts, and Regulations, ArgonneNational Laboratory, Technical Report, 2013). Surfactants are oftenadded to fracturing fluids to enhance their imbibition into reservoirrock.

Safety concerns have forced a shift toward environmentally friendlysurfactants, such as polyoxyethylenated (POE) straight-chain alcoholsR(OC₂H₄)_(x)OH. POEs are biodegradable and, compared to other nonionicsurfactants, have greater tolerance to high ionic strength and hardwater conditions (M. J. Rosen and J. T. Kunjappu, Surfactants andInterfacial Phenomena, Wiley, 2012).

The behavior of POE surfactants changes as POE structures are altered.The differences in POE surfactant behavior can be measured throughsurface/interfacial tension (IFT), emulsification, solubilization, andturbidity of surfactant solutions (Tharwat F. Tadros, AppliedSurfactants: Principles and Applications, Wiley-VCH, 2005).

The decline in IFT using surfactants enhances the dispersion of onephase in another, resulting in the formation of emulsions (S. Kokal,Crude oil emulsions: A state-of-the-art review, SPE Production &Facilities, vol. 20, no. 1, pp. 5-13, 2005). Emulsions andmicroemulsions may cause formation damage, particularly in tightreservoirs with low porosity and permeability. They may also causepressure drops in flow lines and the production of off-spec crude oil(S. Kokal, Crude oil emulsions: A state-of-the-art review, SPEProduction & Facilities, vol. 20, no. 1, pp. 5-13, 2005). Thus,demulsifying surfactants are used in petroleum reservoirs to avoidoperational difficulties during production.

Microemulsion formation depends on a surfactant's surface activity (M.J. Rosen and J. T. Kunjappu, Surfactants and Interfacial Phenomena,Wiley, 2012). As surfactant molecules diffuse from the bulk phase to theoil/brine interface, the surfactants' hydrophobic tails adsorb on theoil phase and their hydrophilic heads partition into the aqueous (brine)phase. Interface partitioning of surfactants increases with increasinghydrophilic chain length, thus increasing the probability ofmicroemulsion formation. For a surfactant to behave as an emulsifier,large surface activity coupled with low IFT values is generallyrequired. This is achieved by increasing the length of the hydrophobicchain (K. Shinoda, H. Saito, H. Arai, Effect of the size and thedistribution of the oxyethylene chain lengths of nonionic emulsifiers onthe stability of emulsions, Journal of Colloid and Interface Science,vol. 35, no. 4, pp. 624-630, 1971). However, although lowering IFTenhances emulsion stability, ultra-low IFT can destabilize the emulsions(P. D. Berger, C. Hsu, and J. P. Arendell, Designing and selectingdemulsifiers for optimum field performance on the basis of productionfluid characteristics, SPE Production Engineering, vol. 3, no. 4, pp.522-526, 1988; H. L. Rosano and D. Jon, Considerations on formation andstability of oil/water dispersed systems, Journal of the American OilChemists' Society, vol. 59, no. 8, 1982; and Y. Yang, K. I. Dismuke andG. S. Penny, Lab and field study of microemulsion-based crude oildemulsifier for well completions, SPE International Symposium onOilfield Chemistry, Texas, USA, April 2009).

Demulsifying efficiency has been shown to result from equal partitioningof surfactants between oil and brine phases (M. A. Kelland, Productionchemicals for the oil and gas industry, CRS Press, 2009; M. A. Krawczyk,D. T. Wasan, and C. S. Shetty, Chemical demulsification of petroleumemulsions using oil-soluble demulsifiers, Industrial & EngineeringChemistry Research, vol. 30, no. 2, pp. 367-375, 1991; P. D. Berger, C.Hsu, and J. P. Arendell, Designing and selecting demulsifiers foroptimum field performance on the basis of production fluidcharacteristics, SPE Production Engineering, vol. 3, no. 4, pp. 522-526,1988). However, weak emulsifiers that are also IFT reducers may also bebeneficial to oil recovery (L. Xu, Q. Fu, Methods for selection ofsurfactants in well stimulation, US 2013/0067999 A1, 2013). Therefore,to generate less emulsion and high oil recovery in asurfactant/rock/oil/brine system, it may be desirable to use surfactantswith none or weak emulsifying ability and low IFT (L. Xu, Q. Fu, Methodsfor selection of surfactants in well stimulation, US 2013/0067999 A1,2013).

Surfactant solubility indicates a surfactant's ability to remain activein brine and to travel into the rock matrix at reservoir temperature.Further, surfactant solubility in aqueous solution may directly impactoil recovery. The solubility of an aqueous nonionic surfactant solutiondepends on temperature and is manifested by a cloud point temperature(CPT).

CPT greatly depends on the arrangement of hydrophobic and hydrophilicparts of surfactants. Cloud point studies of several polyoxyethylene(POE)-type nonionic surfactant solutions in 1-butyl-3-methylimidazoliumtetrafluoroborate suggest that CPT increases with increasing POE chainlength and decreases with increasing hydrocarbon chain length (T. Inoueand T. Misono, Cloud point phenomena for POE-type nonionic surfactantsin a model room temperature ionic liquid, Journal of Colloid andInterface science, vol. 326, no. 2, pp. 483-489, 2008).

The impact of surfactants on parameters like surface/interfacialtension, contact angle, solubility, and emulsification have beenperformed at ambient conditions for applications in oil recovery fromconventional and tight reservoirs (K. Makhanov and H. Dehghanpour, Anexperimental study of spontaneous imbibition in Horn River shales, SPECanadian Unconventional Resources Conference, Calgary, Alberta, Canada,2012; A. Bera, K. Ojha, A. Mandal, and T. Kumar, Interfacial tension andphase behavior of surfactant-brine-oil system, Colloids and Surfaces A,vol. 383, pp. 114-119, 2011; A. Bera, A. Mandal, and B. B. Guha,Synergistic Effect of Surfactant and Salt Mixture on Interfacial TensionReduction between Crude Oil and Water in Enhanced Oil Recovery, Journalof Chemical Engineering Data, vol. 59, no. 1, pp. 89-96, 2013; A.Seethepalli, B. Adibhatla, K. K. Mohanty, Wettability alteration duringsurfactant flooding of carbonate reservoirs, Journal of ChemicalEngineering Data, SPE/DOE Symposium on Improved Oil Recovery, Tulsa,Okla., April, 2004; A. S. Zelenev, CESI Chemical, a Flotek IndustriesCompany, Surface energy of North American Shales and its role ininteraction of shale with surfactants and microemulsions, SPEInternational Symposium on Oilfield Chemistry, Texas, USA, 2011; A. S.Zelenev, L. M. Champagne, M. Hamilton, Investigation of interactions ofdiluted microemulsions with shale rock and sand by adsorption andwettability measurements, Colloids and Surfaces A, vol. 391, no. 1-3,pp. 201-207, 2011). However, these parameters have rarely been examinedat reservoir conditions.

Further, although the adsorption of surfactants at liquid/liquid orliquid/solid interfaces is a dynamic process, surface/interfacialtension, contact angle, solubility, and emulsification have beenprimarily studied at equilibrium conditions (D. Nguyen, D. Wang, A.Oladapo, J. Zhang, J. Sickorez, R. Butler, and B. Mueller, Evaluation ofSurfactants for Oil Recovery Potential in Shale Reservoirs, SPE ImprovedOil Recovery Symposium, Tulsa, Okla., USA, April 2014). In addition,very limited comprehensive studies exist to systematically screensurfactant structure for enhanced oil recovery, particularly for tightreservoirs.

SUMMARY OF THE INVENTION

The invention provides a method for determining an optimal surfactantstructure for oil recovery, comprising evaluating a surfactant's phasebehavior, cloud point, dynamic interfacial tension, static and dynamiccontact angles, spontaneous imbibition, and forced imbibitionexperiments in a porous rock sample.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A. Two-dimensional visualization of pore space of Edwardslimestone. Diameter=2 mm, resolution=1.0 μm.

FIG. 1B. Two-dimensional visualization of pore space of Berea sandstonerock samples. Diameter=3 mm, resolution=1.5 μm.

FIG. 1C. Pore size distribution of Edwards limestone and Berea sandstonerock samples.

FIG. 1D. Scanning electron microscope (SEM) micrographs in backscatteredelectron mode (BSE) mode of Edwards limestone sample in pixel resolutionof 0.5 μm.

FIG. 2. Schematic diagram of the forced imbibition system.

FIG. 3A. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at ambient temperature for ethylene oxide chains ofdifferent lengths (EO: number of ethylene oxides) and a CH₃(CH₂)_(n)alkyl chain wherein n=8-10.

FIG. 3B. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at 80° C. for ethylene oxide chains of different lengths(EO: number of ethylene oxides) and a CH₃(CH₂)_(n) alkyl chain whereinn=8-10.

FIG. 3C. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at ambient temperature for ethylene oxide chains ofdifferent lengths (EO: number of ethylene oxides) and a CH₃(CH₂)_(n)alkyl chain wherein n=10.

FIG. 3D. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at 80° C. for ethylene oxide chains of different lengths(EO: number of ethylene oxides) and a CH₃(CH₂)_(n) alkyl chain whereinn=10.

FIG. 3E. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at ambient temperature for ethylene oxide chains ofdifferent lengths (EO: number of ethylene oxides) and a CH₃(CH₂)_(n)alkyl chain wherein n=11-14.

FIG. 3F. Phase behavior tests with crude oil and surfactant solutions(0.1 wt. %) at 80° C. for ethylene oxide chains of different lengths(EO: number of ethylene oxides) and a CH₃(CH₂)_(n) alkyl chain whereinn=11-14.

FIG. 4. Effect of hydrophilic and hydrophobic chain length on CPT at6840 psi (y=number of alkyl molecules).

FIG. 5A. Effect of changes in the hydrophilic chain length (EO: numberof ethylene oxides) of surfactant molecules on dynamic interfacialtensions at ambient conditions. All surfactant molecules tested had ahydrophobic CH₃(CH₂)_(n) alkyl chain wherein n=8-10. The interfacialtension for tap water/crude oil was determined to be 18.88±0.68 mN/m. Indescending order of its starting point on the y-axis, the datacorresponds to: EO—2.5, base surfactant, EO—6.25, and EO—8.3.

FIG. 5B. Effect of changes in the hydrophilic chain length (EO: numberof ethylene oxides) of surfactant molecules on dynamic interfacialtensions at ambient conditions. All surfactant molecules tested had ahydrophobic CH₃(CH₂)_(n) alkyl chain wherein n=10. The interfacialtension for tap water/crude oil was determined to be 18.88±0.68 mN/m. Indescending order of its starting point on the y-axis, the datacorresponds to: base surfactant, EO—7, and EO—9.

FIG. 5C. Effect of changes in the hydrophilic chain length (EO: numberof ethylene oxides) of surfactant molecules on dynamic interfacialtensions at ambient conditions. All surfactant molecules tested had ahydrophobic CH₃(CH₂)_(n) alkyl chain wherein n=11-14. The interfacialtension for tap water/crude oil was determined to be 18.88±0.68 mN/m. Indescending order of its starting point on the y-axis, the datacorresponds to: EO—3, base surfactant, EO—7.25, and EO—8.2.

FIG. 5D. Effect of changes in the hydrophilic chain length (EO: numberof ethylene oxides) of surfactant molecules on dynamic interfacialtensions at ambient conditions. All surfactant molecules tested had ahydrophobic CH₃(CH₂)_(n) alkyl chain wherein n=11-14. The interfacialtension for tap water/crude oil was determined to be 18.88±0.68 mN/m. Indescending order of its starting point on the y-axis, the datacorresponds to: base surfactant, EO—18, EO—15, and E—8.2.

FIG. 5E. Effect of changes in the hydrophobic chain length of surfactantmolecules on dynamic interfacial tensions at ambient conditions. Allsurfactant molecules tested had an EO—8 hydrophilic chain. Theinterfacial tension for tap water/crude oil was determined to be18.88±0.68 mN/m. In descending order of its starting point on they-axis, the data corresponds to: base surfactant, CH₃(CH₂)_(n) withn=8-10, and CH₃(CH₂)_(n) with n=11-14.

FIG. 5F. Effect of changes in the hydrophobic chain length of surfactantmolecules on dynamic interfacial tensions at ambient conditions. Allsurfactant molecules tested had an EO—9 hydrophilic chain. Theinterfacial tension for tap water/crude oil was determined to be18.88±0.68 mN/m. In descending order of its starting point on they-axis, the data corresponds to: base surfactant, CH₃(CH₂)_(n) withn=10, and CH₃(CH₂)_(n) with n=11-14.

FIG. 6A. Effect of temperature on dynamic IFT of base surfactantsolution/crude oil at reservoir conditions (6840 psi and 120° C.). Indescending order of its starting point on the y-axis, the datacorresponds to: reservoir conditions, ambient conditions.

FIG. 6B. Effect of temperature on dynamic IFT of surfactantsolution/crude oil at reservoir conditions (6840 psi and 120° C.),wherein the surfactant comprises a hydrophobic CH₃(CH₂)_(n) chain withn=10 and a hydrophilic EO—7 chain (EO: number of ethylene oxides). Indescending order of its starting point on the y-axis, the datacorresponds to: reservoir conditions, ambient conditions.

FIG. 6C. Effect of temperature on dynamic IFT of surfactantsolution/crude oil at reservoir conditions (6840 psi and 120° C.),wherein the surfactant comprises a hydrophobic CH₃(CH₂)_(n) chain withn=8-10 and a hydrophilic EO—8 chain (EO: number of ethylene oxides). Indescending order of its starting point on the y-axis, the datacorresponds to: reservoir conditions, ambient conditions.

FIG. 6D. Effect of temperature on dynamic IFT of surfactantsolution/crude oil at reservoir conditions (6840 psi and 120° C.),wherein the surfactant comprises a hydrophobic CH₃(CH₂)_(n) chain withn=11-14 and a hydrophilic EO—18 chain (EO: number of ethylene oxides).In descending order of its starting point on the y-axis, the datacorresponds to: reservoir conditions, ambient conditions.

FIG. 6E. Effect of hydrophilic chain length (EO: number of ethyleneoxides) on dynamic IFT of select surfactant solutions/crude oil atreservoir conditions (6840 psi and 120° C.). In descending order of itsstarting point on the y-axis, the data corresponds to: base surfactant,EO—8, EO—7, EO—18.

FIG. 7A. Effect of surfactant structure on static contact angle onEdwards limestone at ambient conditions with aCH₃(CH₂)_(n)—O—(CH₂CH₂O)_(y)H surfactant. Tap water was used forcomparison.

FIG. 7B. Effect of surfactant structure on static contact angle on Bereasandstone at ambient conditions with a CH₃(CH₂)_(n)—O—(CH₂CH₂O)_(y)Hsurfactant. Tap water was used for comparison.

FIG. 8A. Effect of surfactant structure on advancing dynamic contactangle at reservoir conditions with a CH₃(CH₂)_(n)—O—(CH₂CH₂O)_(y)Hsurfactant. Tap water and base surfactant were used for comparison.

FIG. 8B. Effect of surfactant structure on receding dynamic contactangle at reservoir conditions with a CH₃(CH₂)_(n)—O—(CH₂CH₂O)_(y)Hsurfactant. Tap water and base surfactant were used for comparison.

FIG. 9A. Effect of changes in the hydrophilic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedEdwards limestone rock samples at ambient conditions. All surfactantmolecules tested had a hydrophobic CH₃(CH₂)_(n) alkyl chain whereinn=8-10.

FIG. 9B. Effect of changes in the hydrophilic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedBerea sandstone rock samples at ambient conditions. All surfactantmolecules tested had a hydrophobic CH₃(CH₂)_(n) alkyl chain whereinn=8-10.

FIG. 9C. Effect of changes in the hydrophilic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedEdwards limestone rock samples at ambient conditions. All surfactantmolecules tested had a hydrophobic CH₃(CH₂)_(n) alkyl chain whereinn=11-14.

FIG. 9D. Effect of changes in the hydrophilic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedBerea sandstone rock samples at ambient conditions. All surfactantmolecules tested had a hydrophobic CH₃(CH₂)_(n) alkyl chain whereinn=11-14.

FIG. 9E. Effect of changes in the hydrophobic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedEdwards limestone rock samples at ambient conditions. All surfactantmolecules tested had an EO—8.3 hydrophilic chain (EO: number of ethyleneoxides).

FIG. 9F. Effect of changes in the hydrophobic chain length of surfactantmolecules on spontaneous imbibition of surfactant solutions in saturatedBerea sandstone rock samples at ambient conditions. All surfactantmolecules tested had an EO—8.3 hydrophilic chain (EO: number of ethyleneoxides).

FIG. 10. Spontaneous imbibition in saturated reservoir core samples atambient conditions using tap water, base surfactant, and a surfactantcomprising an EO-18 hydrophilic chain and a hydrophobic CH₃(CH₂)_(n)alkyl chain with n=11-14.

DETAILED DESCRIPTION

The following description and examples are set forth to illustrate theinvention and are not meant to be limiting. Since modifications of thedescribed embodiments incorporating the spirit and the substance of theinvention may occur to persons skilled in the art, the invention shouldbe construed to include all variations within the scope of the claimsand equivalents thereof.

The invention provides a method for determining an optimal surfactantstructure for oil recovery, comprising the steps of: (a) evaluating asurfactant's phase behavior; (b) evaluating the surfactant's solubility;(c) evaluating the surfactant's dynamic interfacial tension in a porousrock sample; (d) evaluating the surfactant's static and dynamic contactangles in the porous rock sample; (e) evaluating the surfactant'sspontaneous imbibition in the porous rock sample; and (f) evaluating thesurfactant's forced imbibition in the porous rock sample.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the method iscarried out with a surfactant concentration above the critical micelleconcentration.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the method iscarried out at a surfactant concentration of 0.1% wt.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the method iscarried out in unconventional reservoir rock.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the method iscarried out in limestone.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the method iscarried out in sandstone.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sphase behavior is evaluated by visualizing a microemulsion middle phaseat ambient and high temperatures.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'ssolubility is evaluated by determining the surfactant's cloud pointtemperature at ambient conditions and at reservoir conditions.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sdynamic interfacial tension is evaluated at ambient conditions and atreservoir conditions.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sdynamic interfacial tension is evaluated by (i) creating a bubble ofcrude oil inside a measurement cell; (ii) capturing oil bubble images;and (iii) fitting drop profiles to the Young-Laplace equation.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein oil bubble imagesare captured at time intervals ranging from 1 second to 100 seconds.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein oil bubble imagesare captured at time intervals ranging from 1 second to 10 seconds.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein oil bubble imagesare captured at time intervals of 5 seconds.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sstatic and dynamic contact angles are evaluated at ambient conditionsand at reservoir conditions.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sstatic contact angle is evaluated by (i) vacuum saturating a rock samplewith crude oil; (ii) immersing the saturated rock sample in brinesolution; (iii) capturing oil bubble images; and (iv) measuring theangles made by a tangent line on the oil bubble images through the brinesolution.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sdynamic contact angle is evaluated by (i) creating bubbles of crude oilinside a measurement cell; (ii) capturing oil bubble images as oilbubbles were injected or retracted beneath a rock sample surface; and(iii) measuring the angles made by a tangent line on the oil bubbleimages through the brine solution using imaging software.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sspontaneous imbibition is evaluated at ambient conditions.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the surfactant'sspontaneous imbibition is further evaluated by (i) saturating a rocksample in crude oil; (ii) exposing the saturated rock sample to brinesolution; and (iii) measuring oil production resulting from brineimbibition.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the forcedimbibition is evaluated by (i) saturating a rock sample with brinesolution; (ii) subjecting the rock sample to primary drainage; (iii)subjecting the rock sample to imbibition; and (iv) subjecting the rocksample to secondary drainage.

A further embodiment of the invention is a method for determining anoptimal surfactant for oil recovery, wherein brine permeability andaverage porosity are determined after saturating the rock sample withbrine solution.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein subjecting therock sample to primary drainage comprises injecting oil into the rocksample after saturating the rock sample with brine solution.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein initial watersaturation is determined after the primary drainage step.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein subjecting therock sample to imbibition comprises injecting a surfactant solution at aconstant flow rate after the primary drainage step.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the flow rate ofsurfactant solution injection in the imbibition step is in the rangefrom 0.001 cc/min to 5 cc/min.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the flow rate ofsurfactant solution injection in the imbibition step is in the rangefrom 0.01 cc/min to 1 cc/min.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein the flow rate ofsurfactant solution injection in the imbibition step is 0.1 cc/min.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein residual oilsaturation is determined after the imbibition step.

A further embodiment of the invention is a method for determining anoptimal surfactant structure for oil recovery, wherein subjecting therock sample to secondary drainage comprises injecting oil into thesample after the imbibition step.

Although the adsorption of surfactants at liquid/liquid or liquid/solidinterfaces is a dynamic process, surface/interfacial tension, contactangle, solubility, and emulsification have been studied at equilibriumconditions and no comprehensive studies have been carried out tosystematically screen surfactant structure for enhanced oil recovery,particularly for tight reservoirs. Because the physical characteristicsof surfactant molecules and the properties of rock reservoirs vary withchanging temperature and pressure conditions of the system (D. H.Johnston, Physical properties of shale at temperature and pressure,Geophysics Journal, vol. 52, no. 10, pp. 1391-1401, 1987), a betterunderstanding of fluid/fluid and rock/fluid interactions at reservoirconditions is essential for the optimization of surfactant formulations.

The invention provides a new method to evaluate the optimum surfactantstructure for oil recovery through a systematic evaluation of phasebehavior, cloud point, dynamic interfacial tension, dynamic contactangle, spontaneous imbibition, and forced imbibition. Using this newmethod, a surfactant structure was identified that is superior to anonionic surfactants commercially deployed in major unconventional oilreservoirs.

In the invention, surfactants of formula I were first assessed throughemulsification and solubilization tests at ambient and reservoirtemperatures. Thereafter, dynamic interfacial tensions and contactangles of crude oil and different surfactant solutions were measured atambient and reservoir conditions. These dynamic interfacial tensions andcontact angles were then used to develop correlations between theinterfacial parameters and the structure of surfactants. Subsequently,spontaneous imbibition and forced imbibition tests were performed in lowpermeability limestone and sandstone samples to study the effect ofselected surfactant structures on oil recovery from porous rocks. Theselimestone and sandstone samples were selected as analogs of dolomiticsiltstone reservoir rock samples to investigate the influence ofmineralogy and pore structure on oil recovery. The study was thenextended to rock samples obtained from an unconventional oil reservoir.Spontaneous imbibition tests were performed and the results were thencompared to those of a base nonionic surfactant formerly deployed in theunconventional oil reservoir. As a result, a relationship between thestructure of the surfactants and oil recovery from limestone, sandstone,and reservoir samples was identified. Lastly, the performance ofshort-listed surfactants was verified through forced imbibition tests atactual reservoir conditions. The results were then compared to those ofthe base surfactant.

Definitions

As used herein, the following terms have the following meanings. If notdefined, a term will have its accepted meaning in the scientificcommunity.

The term “surfactant” refers to a surface-active agent that can adsorbonto surfaces or can interface and reduce interfacial free energies ofthose surfaces, thereby lowering the interfacial tension between aliquid and gas or between two liquids. A surfactant is an amphiphilicorganic compound, meaning an organic compound comprising both ahydrophobic tail and a hydrophilic head. Because surfactants consist ofboth oil-soluble and water-soluble components, they may act asdetergents, wetting agents, emulsifiers, foaming agents, anddispersants.

The term “base surfactant” refers to a commercially available surfactantstructure that has been used in major unconventional oil reservoirs. Thebase surfactant's performance was compared to the performance ofsurfactants used in the invention.

The term “hydrophilic” refers to a tendency to mix with, dissolve in, orbe wetted by water. Hydrophilic molecules tend to be polar and compounds(e.g., surfactants) with a hydrophilic portion tend to be polar at thatportion. A surfactant's hydrophilic portion (e.g., a hydrophilic head)has an affinity for water.

The term “hydrophobic” refers to a tendency to repel water. Hydrophobicmolecules tend to be non-polar and compounds (e.g., surfactants) with ahydrophobic portion tend to be non-polar at that portion. A surfactant'shydrophobic portion (e.g., a hydrophobic tail) does not have affinityfor water.

The term “interfacial tension” (IFT), which may be used interchangeablywith the term “surface tension,” refers to a force that holds a phase'ssurface together.

The term “static interfacial tension” refers to an IFT value inthermodynamic equilibrium independent of time.

The term “dynamic interfacial tension” corresponds to an IFT value thatchanges as a function of time. For liquids with surface-activesubstances (surfactants), the dynamic IFT value can differ from thestatic IFT value.

The term “contact angle” (CA) refers to an angle where a liquid/gas orliquid/liquid interface meets a solid surface. CA values from about 0°to about 90° indicate that a solid surface (e.g., a rock) is water wet.CA values from about 90° to about 180° indicate that a solid surface isoil wet.

“Static contact angles” are measured when a droplet is standing on asolid surface (e.g., rock) and a three-phase boundary (e.g.,oil/brine/rock) is not moving. “Dynamic contact angles” are measuredwhen the droplet is standing on the solid surface and the three-phaseboundary is moving. Dynamic contact angles are referred to as“advancing” when a wetting phase is displacing a non-wetting phase andare referred to as “receding” when a non-wetting phase is displacing awetting phase.

The term “wetting phase” refers to a phase that coats a solid surface.

The term “cloud point temperature” (CPT) refers to the temperature abovewhich a water-soluble surfactant in aqueous solution is no longercompletely soluble in the aqueous solution and precipitates as a secondphase. This precipitation gives the aqueous solution a cloudyappearance.

The term “conventional oil reservoir” refers to a petroleum reservoirthat can produce petroleum, at least initially, without alteringpermeability, viscosity, or rock properties.

The term “unconventional oil reservoir” refers to a petroleum reservoirwith a permeability/viscosity ratio that requires the use of technologyto alter either rock permeability or fluid viscosity to producepetroleum at a commercially competitive rate.

The term “spontaneous imbibition” refers to a process of absorbing awetting phase into a porous medium (e.g., a rock) without the aid ofpressure. Spontaneous imbibition tests are driven by capillary forces inthe porous medium in the absence of applied external forces. Asimbibition takes place in a core sample saturated with crude oil, thewetting phase saturation (i.e., water saturation) increases and oil isrecovered.

The term “forced imbibition” refers to a process of absorbing a wettingphase into a porous medium with the aid of pressure. Forced imbibitiontests include primary drainage, imbibition, and secondary drainage.

The term “ambient conditions” refers to conditions wherein thetemperature is room temperature and the pressure is atmosphericpressure. Room temperature ranges between 15° C. and 30° C., preferablybetween 18° C. and 27° C., and most preferably between 20° C. and 25° C.Atmospheric pressure ranges between 735 mm Hg and 785 mm Hg. Preferably,atmospheric pressure is 760 mm Hg.

The term “reservoir conditions” refers to conditions wherein thetemperature and pressure reflect the temperature and pressure of atarget reservoir. The temperature and pressure of the target reservoirvaries as a function of the reservoir's proximity to the earth's mantleand the composition of the porous medium containing the reservoir.Reservoir temperatures and pressures can be determined by methods knownin the art.

The term “porous rock” refers to a rock that has pores and can absorbfluids. Examples of porous rock include sandstone and limestone.

Materials

The following materials were used to carry out tests in accordance withthe invention.

Preserved reservoir rock samples were employed for contact anglemeasurements and spontaneous imbibition tests. These rock samples werereceived as preserved full cores (4 in. in diameter) and were used asreceived, without further cleaning or conditioning. Saraji et al. show amicrograph of the reservoir samples obtained using high-resolutionscanning electron microscopy (SEM) in back-scattered electron (BSE) modeand an elemental map of the samples generated using energy dispersivespectroscopy (EDS). Using three-dimensional SEM images, the porosity wasmeasured as about 1.5% and the organic content was characterized to beless than 1 vol % (S. Saraji, M. Piri, The representative sample size inshale oil rocks and nanoscale characterization of transport properties,International Journal of Coal Geology, vol. 146, pp. 42-54, 2015). Theelemental map identified the dominant minerals of the reservoir sampleas dolomite, calcite, quartz, and illite clays in order of abundance.X-ray diffraction (XRD) results confirmed the order of mineralogyabundance of the reservoir sample. The preserved rock sample wasidentified as dolomitic siltstone.

Because the targeted reservoir samples were rich in calcite and quartzminerals, outcrop samples were used (i.e., Edwards limestone and Bereasandstone) as test porous media for surfactant screening steps usingspontaneous imbibition. FIGS. 1A and 1B show two-dimensional images ofEdwards limestone and Berea sandstone rock samples obtained usinghigh-resolution X-ray microtomography and scanning electron microscopy.Pore size was characterized by image analysis using AvizoFire™ 9software (FIG. 1C).

A helium porosimeter-permeameter was also used to experimentally measurethe porosity and permeability of the rocks. However, as it is shown inFIG. 1D, Edwards limestone contains micro pores below the resolutions ofthe captured images in FIG. 1A.

Table 1 lists dimensions and basic petrophysical properties of the coresamples employed in the spontaneous imbibition tests.

TABLE 1 Ave. Diameter Ave. Length Ave. Ave. K_(abs) Samples (cm) (cm) ϕ% ^(a) (mD) ^(a) Berea sandstone 2.5 5 23 214 Edwards 2.5 5 20 23limestone Reservoir rock 3.8 2.7 6.65 0.00381 ^(b) ^(a) Porosity (ϕ) andpermeability (K_(abs)) values were measured using helium porosimeter andpermeameter. ^(b) Reservoir rock average permeability (ave. K_(abs))taken from S. Saraji, M. Piri, The representative sample size in shaleoil rocks and nanoscale characterization of transport properties,International Journal of Coal Geology, vol. 146, pp. 42-54, 2015.

Table 2 lists the dimensions and petrophysical properties of Edwardslimestone used in forced imbibition tests. Values were obtained usingthe forced imbibition system.

TABLE 2 Diam- Pore Sample eter Length Ave. K_(abs) Poros- volume no.Exp. (cm) (cm) mD ity % (cm³) 1 Base 3.770 15.98 7.98 21.05 37.55surfactant 2 EO-18 1^(st) 3.777 14.80 14.7 22.91 37.99 3 EO-18 2^(nd)3.765 14.61 13.97 21.50 34.97

The pore-to-throat aspect ratio of Edwards limestone and Berea sandstonewas characterized as 4.76 and 3.89, respectively.

Crude oil from an unconventional reservoir was used, and its propertiesare listed in Table 3. The presented data was obtained from V. Mirchi,S. Saraji, L. Goual, and M. Piri, Dynamic interfacial tension andwettability of shale in the presence of surfactants at reservoirconditions, Fuel, vol. 148, pp. 127-138, 2015, which is incorporated byreference in its entirety. The oil was first centrifuged at 6000 rpm forone hour and then filtered with 0.5 μm metal filters before use.

TABLE 3 Crude oil properties Density 20° C. (g/cc) 0.81 Viscosity (cp)2.804 Asphaltene content (wt. %) 0.45 TAN (mg of KOH/g) 0.23 TBN (mg ofKOH/g) 0.68 Refractive index 1.46

Municipal water was used as the fracturing fluid and reservoir brine wassynthesized to establish initial brine saturation in forced imbibitiontests. The concentrations of the dominant cations and anions inmunicipal water and reservoir brine are listed in Table 4. Measured ionconcentrations were comparable for different samples of municipal water.The pH of tap water and reservoir brine were neutral and their totaldissolved solids (TDS) were about 120 and 320,000 ppm, respectively (V.Mirchi, S. Saraji, L. Goual, and M. Piri, Dynamic interfacial tensionand wettability of shale in the presence of surfactants at reservoirconditions, Fuel, vol. 148, pp. 127-138, 2015).

TABLE 4 Ions Tap water (ppm) Reservoir brine (ppm) Na⁺ 8 102129 Ca²⁺ 4719805 Mg²⁺ 14 1509 Cl⁻ 7 196935 SO₄ ²⁻ 18 — NO₃ ⁻ 10 —

POE-type nonionic surfactants were purchased from Stepan and SigmaAldrich and were used without further purification. The chemical formulaand structure of 14 poly(ethylene oxide) R(OC₂H₄)_(x)OH surfactants withhomologous chain distribution are presented in Table 5. In addition tothese surfactants, a commercially-deployed nonionic surfactant (e.g.,CRS-1080 from ChemEOR) was selected as a base surfactant for comparison.

TABLE 5 Trade Name Chemical structure BIO-SOFT N91-2.5CH₃(CH₂)₈₋₁₀(OC₂H₄)_(2.5)OH BIO-SOFT N91-6 CH₃(CH₂)₈₋₁₀(OC₂H₄)_(6-6.5)OHBIO-SOFT N91-8 CH₃(CH₂)₈₋₁₀(OC₂H₄)_(8.3)OH BIO-SOFT N1-3CH₃(CH₂)₁₀(OC₂H₄)₃OH BIO-SOFT N1-5 CH₃(CH₂)₁₀(OC₂H₄)₅OH BIO-SOFT N1-7CH₃(CH₂)₁₀(OC₂H₄)₇OH BIO-SOFT N1-9 CH₃(CH₂)₁₀(OC₂H₄)₉OH BIO-SOFT N-23-3CH₃(CH₂)₁₁₋₁₂(OC₂H₄)₃OH BIO-SOFT N-23-6.5 CH₃(CH₂)₁₁₋₁₂(OC₂H₄)_(6.5)OHBIO-SOFT EC-639 CH₃(CH₂)₁₁₋₁₃(OC₂H₄)_(8.2)OH BIO-SOFT N-25-3CH₃(CH₂)₁₁₋₁₄(OC₂H₄)₃OH BIO-SOFT N-25-7 CH₃(CH₂)₁₁₋₁₄(OC₂H₄)_(7.25)OHBIO-SOFT N-25-9 CH₃(CH₂)₁₁₋₁₄(OC₂H₄)₉OH Poly(ethylene glycol)(18)tridecyl ether CH₃(CH₂)₁₂(OC₂H₄)₁₈OH

FIG. 2 describes the forced imbibition system. The labels in FIG. 2represent the following components:

P Pressure transducer T Thermocouple 1 Rupture disk 2 Quizix 5000 3 Oilpump 4 Brine pump 5 Large oven 6 Manual overburden pressure pump 7Three-way manual valve 8 Liquid accumulator 9 Three-way Vindum valve 10Core holder 11 Pressure array 12 Two-way manual valve 13 Cooling bath 14Back pressure pump 15 Back pressure regulator valve 16 Graduated burette17 Oil line 18 Brine line 19 Outlet line

Phase Behavior

Phase behavior tests were performed in accordance with the invention toevaluate surfactants' tendency for emulsification.

In the phase behavior tests, test tubes with a brine/oil ratio of 1:1and a fixed salinity of 120 ppm (tap water) were capped and shaken for60 minutes with an incubator shaker at a speed of 350 strokes/minute.For ambient temperatures, the tubes were used at 20° C. For elevatedtemperatures (i.e., reservoir temperatures), the tubes were placed in anoven for 24 hours at 80° C.

Visual phase behavior tests were performed at ambient (20° C.) andelevated temperatures (80° C.) to evaluate surfactants' tendency foremulsification. All visual phase behavior tests were performed at awater/oil ratio of 1:1. A relationship between surfactant structure andemulsification behavior, shown in FIGS. 3A-3F, was identified usingalcohol ethoxylates with varying ethoxylate (EO) side chains andCH₃(CH₂)_(n) side chains.

As shown in FIGS. 3A-3F, for fixed alkyl chains of 8-10, 10, and 11-14,increasing the number of ethylene oxide moieties in the hydrophilicchain increases the amount of microemulsion phase observed in the middleof the test tube. This trend was particularly evident in surfactantswith longer hydrophobic chains. FIGS. 3A-3F exhibit classical Winsortype III phase behavior, wherein a surfactant-rich middle phase coexistswith both the oil and brine phases (J. Eastoe, Advanced surfactants andinterfaces, Bristol UK, 2003). The base surfactant, however, did notproduce a third phase between the oil and brine phases.

FIGS. 3A-3F display the impact of temperature on the phase behavior ofcrude oil and surfactant solutions with different molecular structures.As shown in this figure, temperature affects microemulsion stability.Increasing temperature to 80° C. destabilized the microemulsion phaseproduced by various surfactant structures. Temperature impacts thephysical properties of the crude oil, water, and surfactant molecules,leading to a reduction of surfactant solubility and a breaking of theemulsion/microemulsion phase. Temperature can also increase the kineticenergy of molecules in droplets and induce their coalescence. Jones etal. studied the effect of temperature on the stability of crudeoil/water interfacial films and suggested that an increase intemperature may cause destabilization of crude oil/water interfacialfilms (T. J. Jones, E. L. Neustadter, K. P. Whittingham, Water-In-CrudeOil emulsion stability and emulsion destabilization by chemicaldemulsifiers. Petroleum Society of Canada, April 1978). However, asshown in FIGS. 3A-3F, although increasing the degree of ethoxylation inPOE-type surfactants induced the formation of emulsions/microemulsions,these emulsions/microemulsions were destabilized at elevatedtemperatures. Thus, emulsions will likely not cause operationaldifficulties when highly ethoxylated POE surfactants are used in tightformations at high temperatures.

Cloud Point Temperature

Cloud point temperature tests were performed in accordance with theinvention to evaluate surfactants' solubility.

The solubility and state of orientation between water/oil molecules andhydrophilic/lipophilic parts of surfactants changes as temperature isaltered. The hydration force is inversely dependent on temperature (M.J. Schick, Nonionic surfactants physical chemistry, CRC Press, 1987; K.Shinoda, The correlation between the dissolution state of nonionicsurfactant and the type of dispersion stabilized with the surfactant,Journal of Colloid and Interface Science, vol. 24, no. 1, pp. 4-9, 1967;and T. Mitsui, S. Nakamura, F. Harusawa, Y. Machida, Changes in theinterfacial tension with temperature and their effects on the particlesize and stability of emulsions, Kolloid-Zeitschrift and Zeitschrift fürPolymere, vol. 250, no. 3, pp. 227-230, 1972). In addition, increasingtemperatures causes dehydration of POE chains of nonionic surfactantsolutions, which results in fewer interactions with water molecules andthus exhibits solution cloudiness (T. F. Tadros, Applied surfactants:principles and applications, Wiley-VCH, 2005). Thus, to establish acomprehensive evaluation of surfactant performance, the aqueoussolubility of nonionic surfactants should be assessed at varioustemperatures.

Solubility trends are attributed to hydrophilicity/hydrophobicitycharacteristics of surfactants (F. Curbelo, A. Garnica, E. Neto,Salinity effect in cloud point phenomena by nonionic surfactants used inenhanced oil recovery tests, Petroleum Science and Technology, vol. 31,pp. 1544-1552, 2013; M. J. Rosen and J. T. Kunjappu, Surfactants andInterfacial Phenomena, Wiley, 2012). Hydration of POE chains requireshydrogen bonding with several water molecules depending on the moles ofPOE (H. Schott, Hydration of Micellar Nonionic Detergents, Journal ofColloid and Interface science, vol. 24, no. 2, pp. 193-198, 1967; M. J.Schick, Nonionic surfactants physical chemistry, CRC Press, 1987).

Investigation on the effect of structural arrangement of POE surfactantsincluding alkyl chain and ethylene oxide on solubility of surfactantswas accomplished by cloud point measurements. Surfactant solutions wereinjected into a Hastelloy measurement cell using a Quizix pump. Afterreaching reservoir pressure (6840 psi), surfactant solutions were heatedusing a heating jacket (Glas-col, LLC) firmly wrapped around themeasurement cell. The temperature was gradually raised (≅0.4° C./min)from ambient temperature to 120° C. (reservoir temperature). A mountedresistance temperature detector (RTD) inside the measurement cell (withaccuracy of ±0.1° C.) was used to check the internal temperature.Surfactant solutions were then monitored visually by a digital cameraattached to a microscope. The temperature above which surfactantsolutions became turbid was identified as the CPT.

It was found that lengthening of POE chain for different alkyl chains((CH₂)₈₋₁₀, (CH₂)₁₀, and (CH₂)₁₂) increased the CPT in POE-type nonionicsurfactants. The most hydrophilic surfactant, with 18 ethylene oxides,exhibited a CPT of 109.6° C. Although this surfactant solution becamecloudy at reservoir temperatures, this surfactant exhibited good aqueoussolubility. FIG. 4 also shows that lengthening of the alkyl chain lengthfor different POE chains reduced the CPT in POE-type nonionicsurfactants.

The CPTs of certain selected surfactants were also measured atatmospheric pressure in a water bath. Comparison of the CPTs determinedat atmospheric and reservoir pressures revealed that pressure has anegligible effect on surfactant turbidity. The measured CPTs for theselected surfactants are presented in FIG. 4. The base surfactantexhibited a low CPT (46.1° C.±1.7) in comparison with the selectedsurfactants.

Interfacial Tension

Interfacial tension tests were carried out in accordance with theinvention. Dynamic IFT and contact angles were measured usingrising/captive bubble tensiometry enhanced by image acquisition with ahigh-resolution Charged Coupled Device (CCD) digital camera andapochromatically-corrected lens. The apparatus includes a Hastelloymeasurement cell, a Hastelloy dual-cylinder pulse-free Quizix pump (toprovide constant flow rate and pressure), a temperature control module,a data acquisition computer, an oven, and an in-line density meter(Anton Paar DMA HPM) to measure the density of fluids at actualexperimental conditions. The system tolerates reservoir conditions withpressures and temperatures up to 10,000 psi and 150° C., respectively(V. Mirchi, S. Saraji, L. Goual, M. Piri, Dynamic interfacial tensionand wettability of shale in the presence of surfactants at reservoirconditions, Fuel, vol. 148, pp. 127-138, 2015).

For IFT measurements, after establishing ambient (e.g., 14.7 psi and 20°C.) or reservoir conditions (e.g., 6840 psi and 120° C.) in a cellsaturated with brine, a bubble of crude oil was created inside themeasurement cell through a needle (0.3-1.6 mm outside diameter). Imagesof oil bubbles were captured at 5-second intervals to measure dynamicinterfacial tension. IFT values were obtained by fitting the dropprofile to the Young-Laplace equation using Axisymetric Drop ShapeAnalysis (ADSA) software.

A series of dynamic IFT measurements with municipal water and crude oilwere performed at ambient conditions to examine the surface activity ofselected surfactants. FIGS. 5A-5F present dynamic IFT results of ahomologous series of nonionic surfactant solutions with 0.1% wtconcentration, which is above the critical micelle concentration (CMC)of all the surfactants studied. The size of the hydrophobic andhydrophilic parts of the surfactants were altered independently andtheir impact on oil/brine interfacial tension was investigated.

In addition, the dynamic IFT of certain surfactants was measured atreservoir conditions. In particular, the impact of elevated temperaturesand pressures on the performance of these surfactants was evaluated. IFTvalues of crude oil and surfactant solutions were measured at 6840 psiand 120° C. FIGS. 6A-6E exhibit the measured IFTs at ambient andreservoir conditions.

As shown in FIG. 5A, increasing the degree of ethoxylation (from verysmall amount of 2.5 to 8.3 moles) reduced the IFT between oil and brinein a surfactant series with a fixed hydrocarbon chain length of 8-10methylene units. Similar results were observed when increasing thedegree of ethoxylation in surfactants with alkyl chains comprising 10and 11-14 methylene units (FIGS. 5B and 5C), which may be attributed tosurfactants' solubilization capacity in the aqueous phase. Dissolutionin water is limited for small polar heads (e.g., small ethylene oxideheads), as hydration forces affect solubility. As a result, cloudy brinesolutions are formed. On the other hand, polar head elongation (e.g.,ethylene oxide chain elongation) enhances surfactants' aqueoussolubility, resulting in a greater molecular migration to the interfaceand a reduction in IFT. Surfactant precipitation in brine solution wasobserved at ambient conditions using molecules with EO of 2.5 and 3.

Increase in the degree of ethoxylation from 8 to 18 moles induced anincrease in interfacial tension with fast equilibrium, as shown in FIG.5D. Many factors may impact surfactants' adsorption effectiveness atliquid/liquid interfaces. Surface excess concentration (i.e., surfaceconcentration, Γ_(m)) indicates surfactant effectiveness and isinversely proportional to the area per molecule that surfactants occupyat the interface at surface saturation a_(m) ^(s) (M. J. Rosen and J. T.Kunjappu, Surfactants and Interfacial Phenomena, Wiley, 2012). Changesin the hydrophilic group induce significant structural impact on Γ_(m)(F. Van Voorst Vader, Adsorption of detergents at the liquid-liquidinterface part 1, Transactions of the Faraday Society, vol. 56, pp.1067-1077, 1960). Changes in the hydrophilic chain influence the areaper molecule of polyethylenated nonionic surfactants at the interface.In a surfactant series with a fixed hydrophobic chain length, the areaper molecule rises as the ethylene oxide number increases. Consequently,the oil/brine interface is occupied by fewer surfactant molecules,causing a higher IFT. Moreover, an increase in molecular size results infaster interface saturation and faster equilibrium.

Changes in the hydrophilic/hydrophobic balance (HLB) of a polypropyleneglycol ethoxylate surfactant series leads to IFT changes (P. D. Berger,C. Hsu, and J. P. Arendell, Designing and selecting demulsifiers foroptimum field performance on the basis of production fluidcharacteristics, SPE Production Engineering, vol. 3, no. 4, pp. 522-526,1988). Specifically, an increase in HLB to a certain value results in anIFT reduction, while further increase in HLB results in an IFT increase.

As shown by Equation 1, three typical regions of dynamic IFT reductionexist: (I) induction region, (II) rapid fall region, and (III)mesoequilibrium region (X. Y. Hua, M. J. Rosen, Dynamic surface tensionof aqueous surfactant solutions: I. Basic parameters, Journal of Colloidand Interface Science, vol. 124, no. 2, pp. 652-659, 1988).

log(γ₀−γ_(t))−log(γ_(t)−γ_(m))=n log t−n log t*  (1)

In Equation 1, γ_(t) is the IFT of surfactant solution at time t, γ_(m)is the mesoequilibrium interfacial tension (when γ_(t) is almoststabilized), ≡_(o) is the IFT in the absence of surfactant, and t* isthe required time for IFT to reach half of its value between γ_(o) andγ_(m). The value of n is a constant number related to the structure ofsurfactants and correlates to the difference between surfactants'adsorption and desorption. Increasing nonionic surfactants'polyoxyethylene chain length reduces the value of n (T. Gao, M. J.Rosen, Dynamic surface tension of aqueous surfactant solutions: 7.physical significance of dynamic parameters and the induction period,Journal of Colloid and Interface Science, vol. 172, no. 1, pp. 242-248,1995).

At a constant surfactant concentration, the maximum rate of change insurface tension decreases as n declines. Therefore, increasing EO chainlength or decreasing n induces a smaller difference between equilibriumIFT and IFT at any given time, resulting in instantaneous equilibrium.

Values of t* were calculated for a series of surfactants, as shown inTable 7. An increase in the degree of ethoxylation was observed toreduce the time required for IFT to reach half of its value.

TABLE 7 Impact of POE chain length on time and oil recovery. No. of CH₂No. of EO t* (min.) Recovery from Edwards (%)  8-10 2.5 16.5 42.69 ±1.37 6 12.3 44.94 ± 1.16 8 11.6 45.41 ± 1.5  11-14 3 23 41.69 ± 2.297.25 9.3  45.7 ± 1.16 8.2 7.83 46.78 ± 1.24 18 3.5  48.8 ± 1.61 Basesurfactant — 15.66 43.87 ± 1.5 

FIGS. 5E and 5F illustrate the impact of increasing the hydrophobicchain of surfactants on oil/brine IFT. It was observed that addition ofmethylene groups in the alkyl chain, lowers the IFT. In a surfactantseries with a fixed oxyethylene chain length, an increase in alkyl chainlength results in minor increases in surfactant adsorption effectivenessat the interface, which may be due to effects on the surface excessconcentration by the number of methylene groups in the alkyl chain. (D.Attwood, A. T. Florence, Surfactant systems: their chemistry, pharmacyand biology, Lippincott Williams & Wilkins, 1983; M. J. Rosen and J. T.Kunjappu, Surfactants and Interfacial Phenomena, Wiley, 2012).

In FIGS. 6A-6D, the difference between IFT values measured at ambientconditions and at reservoir conditions decreased with increasingsurfactant hydrophilicity. That is, surfactants with higher CPTsexhibited smaller differences between IFT values measured at ambientconditions and at reservoir conditions. A larger area coverage bysurfactant molecules reduces surfactant concentration at the oil/brineinterface. Therefore, the surface activity of surfactants at highertemperature declines, leading to greater IFT (M. J. Rosen and J. T.Kunjappu, Surfactants and Interfacial Phenomena, Wiley, 2012).

As shown in FIGS. 5A-5F, at ambient conditions, both the base surfactantand surfactants with shorter hydrophilic chains produced smaller IFTsthan surfactants with large hydrophilic heads. However, IFT ofsurfactants with a large hydrophilic head remained unchanged atreservoir conditions, while the other surfactants' IFT increased (FIG.6D). Thus, surfactants with the highest hydrophilicity had the lowestIFTs at reservoir conditions and were found to be more suitable forimproved oil recovery applications.

Contact Angle

Contact angle tests were performed in accordance with the invention onthe surfaces of Edwards limestone, Berea sandstone, and reservoir coresamples.

Prior to dynamic contact angle measurements, reservoir rock samples werecut using a precision saw and polished to create a smooth surface and toremove irregular and uneven areas. The surface roughness of thereservoir rock samples was expected to be lower than 1 μm (V. Mirchi, S.Saraji, L. Goual, and M. Piri, Dynamic interfacial tension andwettability of shale in the presence of surfactants at reservoirconditions, Fuel, vol. 148, pp. 127-138, 2015). The rock substrate wasthen placed on a sample holder inside the measurement cell and the cellwas filled with brine solution.

For dynamic contact angle measurements, images were captured while oilbubbles were slowly swelled or shrunk beneath the rock surface using aQuizix pump. For static contact angle measurements, limestone andsandstone rock samples were cut and then vacuum saturated with crudeoil. The saturated samples were then immersed in brine solution.

After crude oil was produced from the sample by brine imbibition, staticcontact angles were captured with a CCD camera equipped with a suitablemagnifying lens. The captured images of dynamic and static bubbles wereanalyzed using ImageJ software, and the contact angle was determined bymeasuring the angles made by the tangent line on the bubbles through thebrine phase. A detailed procedure for contact angle determination isprovided in V. Mirchi, S. Saraji, L. Goual, and M. Piri, Dynamicinterfacial tension and wettability of shale in the presence ofsurfactants at reservoir conditions, Fuel, vol. 148, pp. 127-138, 2015,which is incorporated herein by reference in its entirety.

Static contact angles of crude oil on limestone and sandstone samplesimmersed in different surfactant solutions (0.1 wt. %) were measured atambient conditions and are shown in FIGS. 7A and 7B.

Dynamic contact angle measurements were performed at reservoirconditions to investigate the effect of various surfactant structures onthe wettability of reservoir rock surface. Contact angles of crude oilbubbles, which were growing and shrinking beneath the rock surface at aslow flow rate, were measured on prepared rock surfaces in the presenceof surfactant solutions (captive bubble). The presented data for eachsurfactant in FIGS. 8A and 8B is the average value calculated from 30measured contact angles, each obtained at a 5-second interval.

Lengthening the ethylene oxide side of nonionic surfactants was found tohave no impact on the wettability state of Edwards limestone or Bereasandstone (FIGS. 7A and 7B). Similarly, the dolomitic siltstone rocksurface of the reservoir rock sample exhibited a water-wet behavior withadvancing (oil shrinking) and receding (oil expanding) contact angles of43.19 and 23.19 degrees, respectively. The dynamic contact angle valuesin FIGS. 8A and 8B remained nearly unchanged with tap water anddifferent surfactant structures. This suggests no sensitivity ofreservoir rock's wettability to nonionic surfactants containing POEchains. Earlier comparison of anionic and nonionic surfactant adsorptionon reservoir rock samples demonstrated that nonionic surfactantadsorption is smaller than anionic surfactant adsorption due to weakerelectrostatic interactions with functional groups at the rock surface(V. Mirchi, S. Saraji, L. Goual, and M. Piri, Dynamic interfacialtension and wettability of shale in the presence of surfactants atreservoir conditions, Fuel, vol. 148, pp. 127-138, 2015).

Spontaneous Imbibition

Spontaneous imbibition tests were performed in accordance with theinvention on cylindrical Edwards limestone, Berea sandstone, andreservoir core samples at ambient conditions. The Edwards limestone andBerea sandstone cores were initially vacuumed using a robust vacuum pump(TRIVAC Vane, ˜10⁻⁷ psi) for one day, and the reservoir core sampleswere initially vacuumed using a robust vacuum pump for three days.Thereafter, crude oil was gradually introduced to the cores inside thevacuum cell until the entire rock was immersed in crude oil, whichresulted in 97-99% oil saturation for the Edwards limestone and Bereasandstone cores and in 70-80% for reservoir core samples.

The saturated cores were then placed in glass imbibition cells with avolume accuracy of 0.1 cc and filled with brine from the top. A thinV-shaped glass spacer beneath each saturated core ensured that all corefaces were exposed to the brine solution. Produced oil volume wasrecorded as a function of time until no more production was observed.Oil production by spontaneous imbibition of brine solution was reportedas a percentage of the original oil in place.

Forced Imbibition

Forced imbibition tests were performed in accordance with the invention.

Spontaneous imbibition is impacted by capillary forces in the porousmedium (i.e., a rock sample) in the absence of any applied externalforces. As imbibition takes place in a core sample saturated with crudeoil, the wetting phase (i.e., water) saturation increases with a ratethat depends on wettability, pore size distribution, IFT of fluids, andother factors. Each set of tests with Edwards limestone and Bereasandstone rocks was conducted with core samples of similar wettingstate, permeability, and pore size distribution, while IFTs were variedusing different surfactants.

The results of spontaneous imbibition tests in Edwards limestone andBerea sandstone rock samples with reservoir crude oil and differentsurfactant solutions (0.1 wt %) are shown in FIGS. 9A-9F. The results ineach case are the average of 3-4 measurements with an error bar showingthe variations.

Imbibition tests on reservoir rock samples were performed with asurfactant comprising EO=18 and CH₂=11-14. The spontaneous imbibitionresults obtained with this surfactant were compared to those of the basesurfactant and tap water (FIG. 10).

FIG. 2 shows a schematic diagram of the forced imbibition apparatus usedin the forced imbibition tests. The forced imbibition apparatuscomprises three Quizix pumps, two pumps for oil and water injection andone pump for back pressure regulation, two pressure transducers, adome-loaded back pressure regulator, a manual over-burden pressure pump,a cooling bath, and a burette for fluid collection. The core assemblywas mounted in an oven with temperature control to reach experimentalconditions.

Edwards limestone core samples were used for flow tests. Edwardslimestone blocks were cut to achieve core samples 3.7 cm in diameter and15 cm long. The Edwards limestone core samples were then flushed withCO₂ and vacuumed to remove trapped gases.

Synthetic reservoir brine was injected into the Edwards limestone andBerea sandstone core samples with gradually increasing flow rate at bothambient and reservoir conditions. Absolute brine permeability wasquantified by measuring the pressure differential across the coresamples. Average porosity was determined using the total volume of thecore samples and the weight difference of the core samples before andafter saturation with brine. After the core samples were saturated withreservoir brine at reservoir conditions, each core sample was subjectedto primary drainage, imbibition, and secondary drainage tests. Tomitigate the effect of potential gravity segregation, brine was injectedfrom the bottom of the core holder.

Initial water saturation (S_(wi)) was established by oil injection(primary drainage) at reservoir conditions and was determined to beabout 23% for the core samples. Different surfactant solutions wereinjected at a constant flow rate of 0.1 cc/min (imbibition). This flowrate provided a capillary-dominated displacement regime with an averagecapillary number of 1.355×10⁻⁶ for all the IFT values used in thisstudy. The capillary numbers were calculated using Equation 2.

$\begin{matrix}{N_{c} = \frac{\mu_{b}u_{b}}{\sigma_{ob}\varnothing}} & (2)\end{matrix}$

Variables μ_(b), u_(b), Ø and σ_(ob) respectively represent viscosity,Darcy velocity of brine, sample porosity, and the interfacial tensionbetween oil and brine. Residual oil saturation (S_(or)) was determinedat the end of the imbibition stage by calculating the volume differencebefore and after imbibition and the weight difference of the coresamples before and after imbibition.

The last stage of flooding tests included oil injection (secondarydrainage) at reservoir conditions in order to simulate the flowbackprocess after hydraulic fracturing and to assess the influence ofdifferent surfactant structures on remaining water saturation (S_(wr)).The outlet and confining pressures of the core samples were maintainedat 6840 psi and 8100 psi, respectively throughout secondary drainage.

Three sets of flooding tests (i.e., three sets of tests comprising theprimary drainage, imbibition, and secondary drainage steps) wereperformed on three low-permeability Edwards limestone core samples atreservoir conditions. These Edwards limestone samples were cut from thesame block, which was acquired from a quarry in Texas. The physicalproperties and dimensions of the rock samples are listed in Table 2.Table 6 summarizes the results of the forced imbibition tests, whichinclude endpoint-relative permeability values, final fluid saturations,and recovery factor percentages for all three steps of the floodingtests. All the forced imbibition tests were performed at a brine flowrate of 0.1 cc/min, providing an average capillary number of 1.355×10⁻⁶.

TABLE 6 Fluid saturations, end-point relative permeability, and recoveryfactors obtained at the end of each step of forced imbibition atreservoir conditions. Base surfactant EO-18 (1^(st) test) EO-18 (2^(nd)test) S_(w) k_(rw) k_(ro) RF (%) S_(w) k_(rw) k_(ro) RF (%) S_(w) k_(rw)k_(ro) RF (%) 1^(st) Drainage 0.233 — 0.5  — 0.234 — 0.41 — 0.238 — 0.45— Imbibition 0.601 0.084 — 47.98 0.654 0.12 — 54.83 0.643 0.065 — 53.152^(nd) Drainage 0.231 — 0.29 61.56 0.279 — 0.31 57.83 0.270 — 0.24 58.01

The effect of hydrophilic/hydrophobic chain length of nonionicsurfactants on oil recovery from Edwards limestone core samples wasstudied through spontaneous imbibition tests. Surfactants with shorthydrophilic chains (e.g., surfactants with EO of 3) resulted in only aslight improvement in final oil production compared to tap water andresulted in no improvement in final oil production compared to the basesurfactant in limestone samples (FIG. 9A). Surfactants with EO of 6.25and 8.3 produced a higher amount of oil than the base surfactant andsurfactants with short hydrophilic chains (e.g., surfactants with EO of3). Similar results were observed for surfactants with alkyl chain of11-14 (FIG. 9C).

Analogous behavior was observed during imbibition tests in Bereasandstone samples. FIG. 9B shows that brine imbibition in the presenceof surfactants with short hydrophilic chains (e.g., surfactants with EO2.5) is slower than brine imbibition in the presence of either municipalwater or base surfactant, which may be a result of surfactantprecipitation and partial pore- and throat-blockage.

As shown in FIGS. 7A, 7B, 8A, and 8B, the impact of POE surfactantstructure on contact angle results is small. Thus, a high surfaceactivity may explain the strong imbibition induced by lengthening thehydrophilic chain of surfactants.

Lower equilibrium IFT was observed to result in higher oil recovery,suggesting that oil production correlated inversely to equilibrium IFTvalues. Although IFT reduction rates of surfactants with low to mediumhydrophilic chains (EO=3-8.2) were similar, equilibrium IFTs for thesesurfactants were different. Thus, equilibrium IFT for surfactants withlow to medium hydrophilic chain may explain the improvement in oilproduction observed upon increasing EO chain length in surfactants fromlow to medium.

In tests that lengthened the hydrophilic side chain from medium to high(EO 8.2-18) in a surfactant series with the same hydrophobic chain,surfactants with longer hydrophilic chains (e.g., EO 18) provided higheroil production from Edwards limestone samples than surfactants withshorter hydrophilic chains (e.g., EO 8.2) (FIG. 9C). In contrast totests that lengthened the hydrophilic side chain from low to medium,tests that lengthened the hydrophilic side chain from medium to highexhibited a correlation between superior production, higher IFT values,and faster IFT equilibration.

Table 7 shows the relationship between recovery values and lengtheningsurfactants' hydrophilic chain. As shown in the table, an increase inethoxylation degree reduced the time required for IFTs to reach half oftheir value and sped up oil production. Thus, greater oil productionfrom Edwards limestone was observed when IFT reduction regions(including induction, rapid fall, and mesoequilibrium) are close to eachother, creating a flat line for dynamic IFT values (FIGS. 5A-5F).Although lengthening surfactants' hydrophilic side chain from medium tohigh (EO 8.2-18) sped up brine imbibition in Berea sandstone samples(FIG. 9D), it did not significantly affected final oil production.

FIGS. 9E, 9F, and Table 7 demonstrate an enhancement in oil productionby increasing the number of methylene groups from 8-10 to 11-14. Theimprovement in oil recovery accorded with the corresponding IFT values.An increase in surfactants' lipophilic characteristics may induce aminor increase in the surfactants' surface activity.

Impact of Rock Type on Oil Recovery.

The Edwards limestone and Berea sandstone samples have differentmineralogies and pore structures. Based on the pore size distributionanalysis shown in FIG. 1C, Edwards limestone has a wider pore sizedistribution (approx. 1-400 μm) than that of Berea sandstone (approx.1-300 μm). Edwards limestone also includes two distribution spikes(i.e., bimodal distribution), one spike on a small pore size range(i.e., <5 μm) and the other spike on a larger range (i.e., ≥250 μm). SEMimages confirm the existence of micro pores in this rock (FIG. 1D).Although the Edwards core samples had lower permeability than the Bereasandstone samples, the presence of micro pores in the Edwards coresamples may have improved oil production rates at initial stages. Micropores may have provided better brine imbibition accessibility to smalloil-filled pores at initial imbibition stages.

Pore size distribution impacts the relationship between the capillarydesaturation curve (CDC) and residual non-wetting saturations (M.Khishvand, M. Akbarabadi, and M. Piri, Micro-scale experimentalinvestigation of the effect of flow rate on trapping in sandstone andcarbonate rock samples, Advances in Water Resources, vol. 94, pp.379-399, 2016; L. W. Lake, Enhanced oil recovery, Prentice Hall, 1989).The inflection point in CDC for carbonates (e.g., limestones), whichhave a wider pore size distribution, happens at lower capillary numbersthan the inflection point in CDC for sandstones (L. W. Lake, Enhancedoil recovery, Prentice Hall, 1989). Therefore, increasing the capillarynumber by reducing IFT in Edwards limestone has a greater impact on theresidual oil saturation compared to that of Berea sandstones. As such,using surfactant solutions led to oil recovery from Berea sandstonesimilar to those of tap water with no surfactant. However, narrower poresize distribution, smaller pore-to-throat aspect ratio, and lowercontact angles (FIGS. 7A and 7B) in Berea sandstone led to greater oilproduction than in Edwards limestone (51% oil recovery compared to 45%)(M. Khishvand, M. Akbarabadi, and M. Piri, Micro-scale experimentalinvestigation of the effect of flow rate on trapping in sandstone andcarbonate rock samples, Advances in Water Resources, vol. 94, pp.379-399, 2016; Y. Tanino and M. J. Blunt, Capillary trapping insandstones and carbonates: Dependence on pore structure, Water ResourcesResearch, vol. 48, 2012; G. R. Jerauld, and S. J. Salter, The effect ofpore-structure on hysteresis in relative permeability and capillarypressure: Pore-level modeling, Transport in Porous Media, vol. 5, pp.103-151, 1990).

The presence of different minerals in the Edwards limestone and Bereasandstone samples did not affect the interfacial properties of nonionicsurfactant solutions and crude oil. For Edwards limestone samples,equilibrated tap water and unequilibrated tap water provided similardynamic IFT values with crude oil (i.e., 18.88±0.68 mN/m). In addition,nonionic surfactants have only minor interactions with differentminerals. Thus, rock sample pore structure was determined to influencesurfactant solution/oil displacements more than rock sample mineralogy.

In ultra-tight rocks, capillary force impacts fluid displacements. Assuch, the impact of gravity segregation on conventional rocks must bedetermined. When the bond number (the ratio of buoyancy to capillaryforces) is low (e.g., ≤10⁻⁶) fluid flow is capillary controlled (D. S.Schechter, Z. Denqen, F. M. Orr, Capillary imbibition and gravitysegregation in low IFT systems, SPE Annual Technical Conference andExhibition, October, Dallas, Tex., 1991). Bond number can be calculatedfrom Equation 3 (N. R. Morrow, and B. Songkran, Effect of viscous andbuoyancy forces on non-wetting phase trapping in porous media, SurfacePhenomena in Enhanced Oil Recovery, edited by D. O. Shah, pp. 387-411,Plenum, New York, 1981).

$\begin{matrix}{B_{o} = \frac{\Delta_{pg}K}{\gamma}} & (3)\end{matrix}$

In Equation 3, K is intrinsic (absolute) permeability of the porousmedium, γ is interfacial tension, Δ_(ρ) is density difference and g isacceleration due to gravity, respectively.

For the lowest IFT determined, the calculated bond number was 1.31×10⁻⁸.For the highest IFT determined, the calculated bond number was7.3×10⁻¹⁰. The calculated bond numbers for the lowest and highest IFTsindicate that fluid flow is under a capillary-dominated regime. Gravitysegregation was not responsible for oil production, as oil was producedfrom all sides of the core samples and not just from the top.

Moreover, the unconventional reservoir core samples have a pore sizedistribution similar to the Edwards limestone core samples: one smallpore diameter peak and one large pore diameter peak (M. Akbarabadi, S.Saraji, and M. Piri, Nano-scale experimental investigation of in-situwettability and spontaneous imbibition in ultra-tight Reservoir Rocks,2016, To be submitted). In tight rocks, the presence of poorly connectednanopores and micro fractures slows down the brine imbibition into theporous media, which creates differences in the rate and final productionof oil with various surfactants. As seen in FIG. 10, the selectedsurfactant provided a faster and higher production from reservoir coresample than the base surfactant or tap water. Oil recovery fromreservoir rock sample with surfactants increased by up to 6% compared tothat of base surfactant and by up to 22% compared to that of tap waterwithout surfactant. As such, the method of the invention proposed can beapplied on to screen surfactants for hydraulic fracturing process intight samples.

Based on the mineralogy of the reservoir rock sample, pore sizedistribution results, and spontaneous imbibition trends, Edwardslimestone was selected for additional tests at reservoir conditions. Inforced imbibition tests at reservoir conditions (Table 6), oilproduction due to imbibition increased by 5-6% using EO-18 surfactantcompared to the base surfactant. The increase in oil recovery with EO-18may be attributed to an instantaneous reduction in IFT and a subsequentrapid decrease in the threshold capillary pressure in the pore space ata fixed brine flow rate (0.1 cc/min). During flowback tests on thereservoir rock sample at reservoir conditions, brine volumes recoveredby EO-18 were comparable to those recovered by base surfactant.

Table 6 also lists the end-point relative permeability data. Theend-point water relative permeability increased as residual oilsaturation was reduced from the first waterflooding test (basesurfactant) to the second waterflooding test (EO-18). However, k_(rw)decreased in the third waterflooding test. The variation in end-pointrelative permeability values in the third waterflooding test may havebeen caused by differences in the samples used.

For all the forced imbibition tests, k_(ro) values at the end of thesecond drainages are lower than k_(ro) values of the first drainages,despite the similar initial water saturations for both drainages. Thedifferences in k_(ro) values at the end of the drainages may be causedby trapping of the non-wetting phase in pores and throats duringimbibition process prior to the second drainage.

A new systematic and integrated procedure was introduced to study theinfluence of surfactant structures on interfacial properties and oilrecovery of oil/brine/rock systems using conventional and unconventionalrocks. Hydrophobic and hydrophilic parts of POE-type nonionicsurfactants were altered, while solubilization, emulsification, anddynamic IFT were investigated at both ambient and reservoir conditions.Spontaneous imbibition tests were also conducted in relatively lowpermeability limestone and sandstone rocks to study the impact ofmineralogy and pore structure on oil recovery. The performances of thesesurfactants were compared to that of a base surfactant commerciallydeployed in the targeted unconventional reservoir.

Surfactants with greater degree of hydrophilicity were more appropriateat reservoir conditions because their structures tolerate highertemperatures. Although EO chain elongation increased the surfactants'emulsification propensity at ambient conditions, no microemulsions wereobserved at high temperature using reservoir crude oil and tap water.

Surfactants that reduced the IFT rapidly were more effective thansurfactants that reduced the IFT to lower values but over a longerperiod of time. For example, although the highly ethoxylated POE-typesurfactant did not provide the lowest IFT, this surfactant rapidlyreached equilibrium upon introduction of crude oil to the surfactantsolutions and resulted in the significantly improved oil recovery.

Increasing the hydrophilicity of surfactants from low to high rangeresulted in higher oil recovery during spontaneous imbibition tests.Surfactant increased the oil production from reservoir rock sample by upto 22% compared to tap water and by up to 6% compared to the basesurfactant.

Spontaneous imbibition behavior of oil/brine in rock samples usingdifferent nonionic surfactants was affected more significantly bypore-throat structure than mineral type. Applying various nonionicsurfactant structures did not affect the original wettability state ofreservoir rock at reservoir conditions.

The proposed methodology for surfactant evaluation was verified throughforced imbibition tests at reservoir conditions. The optimum surfactantstructure improved oil recovery by 5-6% compared to the base surfactant.

1. A method for determining an optimal surfactant structure for oilrecovery, comprising the steps of: (a) evaluating a surfactant's phasebehavior; (b) evaluating the surfactant's solubility; (c) evaluating thesurfactant's dynamic interfacial tension, wherein the surfactant'sdynamic interfacial tension is evaluated by: (c-1) creating a bubble ofcrude oil inside a measurement cell, (c-2) capturing oil bubble images,and (c-3) fitting drop profiles to the Young-Laplace equation; (d)evaluating the surfactant's static and dynamic contact angles on aporous rock sample; (e) evaluating the surfactant's spontaneousimbibition in the porous rock sample; and (f) evaluating thesurfactant's forced imbibition in the porous rock sample.
 2. The methodas in claim 1, wherein the method is carried out with a surfactantconcentration above a critical micelle concentration.
 3. The method asin claim 1, wherein the surfactant's phase behavior is evaluated byvisualizing a microemulsion middle phase at ambient and hightemperatures.
 4. The method as in claim 1, wherein the surfactant'ssolubility is evaluated by determining the surfactant's cloud pointtemperature from ambient conditions to reservoir conditions.
 5. Themethod as in claim 1, wherein the surfactant's dynamic interfacialtension is evaluated at ambient conditions and at reservoir conditions.6. (canceled)
 7. The method as in claim 7, wherein oil bubble images arecaptured at time intervals ranging from 1 second to 100 seconds.
 8. Themethod as in claim 1, wherein the surfactant's static and dynamiccontact angles are evaluated at ambient conditions and at reservoirconditions.
 9. The method as in claim 1, wherein the surfactant's staticcontact angle is evaluated by (d-1) vacuum saturating a porous rocksample with crude oil; (d-2) immersing the saturated porous rock samplein a brine solution; (d-3) capturing oil bubble images as they wereproduced; and (d-4) measuring angles made by a tangent line on the oilbubble images through the brine solution.
 10. The method as in claim 1,wherein the surfactant's dynamic contact angle is evaluated by (d-5)creating bubbles of crude oil inside a measurement cell; (d-6) capturingoil bubble images as oil bubbles were injected or retracted beneath aporous rock sample surface; and (d-7) measuring angles made by a tangentline on the oil bubble images through a brine solution using imagingsoftware.
 11. The method as in claim 1, wherein the surfactant'sspontaneous imbibition is evaluated at ambient conditions.
 12. Themethod as in claim 11, wherein the surfactant's spontaneous imbibitionis further evaluated by (e-1) saturating a porous rock sample in crudeoil; (e-2) exposing the saturated porous rock sample to a brinesolution; and (e-3) measuring oil production resulting from brineimbibition.
 13. The method as in claim 1, wherein the surfactant'sforced imbibition is evaluated by (f-1) saturating a porous rock samplewith a brine solution; (f-2) subjecting the porous rock sample toprimary drainage; (f-3) subjecting the porous rock sample to imbibition;and (f-4) subjecting the porous rock sample to secondary drainage. 14.The method as in claim 13, further comprising the step of (f-1-1)determining brine permeability and average porosity after step (f-1).15. The method as in claim 13, wherein step (f-2) comprises injectingoil into the porous rock sample.
 16. The method as in claim 13, furthercomprising the step of (f-2-1) determining initial water saturationafter step (f-2).
 17. The method as in claim 13, wherein step (f-3)comprises injecting a surfactant solution at a constant flow rate. 18.The method as in claim 17, wherein the flow rate of surfactant solutioninjection in the imbibition step is in a range from 0.001 cc/min to 5cc/min.
 19. The method as in claim 13, further comprising the step of(f-3-1) determining residual oil saturation after step (f-3).
 20. Themethod as in claim 13, wherein step (f-4) comprises injecting oil intothe porous rock sample after step (f-3).